Shale oil companies are currently building state-of-the-art gathering infrastructure to transport oil and natural gas from the wells through an oil gathering system to a central oil stabilization facility to eliminate truck traffic and condensate tank emissions. A portion of fracturing fluids and sand that returns to the surface (slickwater and proppant backflow) may accumulate in this new-built pipeline infrastructure and cause severe pitting corrosion. Also, paraffin and wax deposits may cause operational problems in various parts of the oil gathering system. In offshore production systems, production streams frequently contain organic/inorganic solids and water causing corrosion and wax buildup in subsea pipelines, which are unpiggable in many cases.
We propose a novel system for removing solids, wax, sludge, and other unwanted fluids causing corrosion and/or flow assurance issues in oil and gas gathering systems, including manifolds and unpiggable process lines. The system comprises one component that generate fluid batches at the inlet of the flowlines and a model-based controller component that determines the launch time of fluid batches such that the batches generated in the flowlines are merged into one batch in the gathering pipeline or production manifold. The controller simulates the fluid batches moving along the flowlines using a real-time simulation model and provides automatic control of the systems generating the fluid batches. The dose of corrosion or wax inhibitors is automatically adjusted to maintain a predetermined concentration of the chemical in response to a variation of the rate of water production in the well.
Scale-model test results and real-time simulations of system operation are presented. The stationary bed of solids formed in the production manifold and process lines is converted into a series of solids dunes that slowly move toward the separator. This effect dramatically reduces the likelihood of internal corrosion. Also, the risk of wax deposition reduces because the internal surface of the pipe is continuously flushed by hot water batches. This technology is applicable for existing and new-build pipeline infrastructure and virtually does not have limitations regarding the design of the oil or gas gathering system, operating pressure and temperature. As a result, the production manifold itself and unpiggable process lines are efficiently flushed with produced water.
Storage tanks are the primary means for storing large volumes of liquids and gaseous products. Metal
loss from internal and external corrosion can reduce the service life of a tank. It is important to maintain
the integrity of steel storage tanks for safety, economic, and environmental reasons.
Saudi Aramco implemented three different scenarios of cathodic protection (CP) during bottom plate
replacement for three typical tanks. The tanks’ bottom plates were replaced based on thickness
measurements and visual inspection that revealed severe corrosion from soil. The main reason for
such corrosion was due to the asphalt layer underneath the tank. It was considered during the
replacement of the bottom plate to provide a reliable external (CP) and leak detection system. The
purpose of this paper is to demonstrate the experience gained from executing CP upgrades, and to
provide the best option to ensure integrity, cost saving and fewer shutdown periods.
Upstream oil and gas companies operate oil gathering systems comprising a flowline network and process facilities that transport the flow of produced fluids from the wells to a main processing plant. The frequency of corrosion related leaks has increased recently despite a corrosion inhibitor is injected at the wellhead into all flowlines. A root-cause analysis conducted by several companies revealed that severe internal corrosion was caused by a low fluid flow velocity an increasing water cut and the presence of sulfate-reducing bacteria (SRB) in the production streams. Nevertheless it was not clear why some of the flowlines may leak while others do not leak despite the composition of produced fluids principal design parameters (diameter and length) dosage of corrosion inhibitor and environmental conditions of the flowlines are similar. A diagnostic analysis of different oil flowlines of was carried out to gain an understanding of why a first group of oil flowlines is developing leaks and why a second group of flowlines has not experienced leaks. The methodology used for the diagnostic analysis comprises 1) Ultra-High Definition simulation of 3-phase or 4-phase flow of gas oil water and solids; 2) 3D imaging of phase distributions inside critical sections of the oil flowlines as per NACE ICDA; 3) mapping adverse operational conditions; and 4) the determination of probability of failure in the critical sections based on criteria depending on the severity of operating conditions inside and outside the flowlines. It was found that multiple sections were exposed to stagnant water and/or had a fraction of internal surface area covered by a stationary bed of solids (formation solids produced from the well). The identified causes of potential leaks comprise the following failure mechanisms: a) metal loss caused by colonies of SRB b) composed load acting on the pipe wall and c) cyclic" thermal expansion/contraction of the flowlines due to seasonal ambient temperature variations. One of the surprising findings of this study was that a shorter flowline with a lower water cut may have multiple leaks while a longer flowline with a higher water may not leak at all approximately for the same period after commissioning. This result was explained with help of maps of adverse operational conditions constructed for the two groups of flowlines. Immediate corrective mitigation actions and preventive actions were implemented to reduce leak frequency including the installation of a novel automatic flushing system.